Segmented fluid end plunger pump

ABSTRACT

A fluid end for a fracturing pump includes a plurality of segments coupled together along a discharge axis, each segment of the plurality of segments having a plurality of suction bores. The fluid end also includes respective interfaces between segment pairs formed by adjacent segments of the plurality of segments, the interfaces coupling the segment pairs together. The fluid end further includes respective access areas proximate the respective interfaces, the respective access areas configured to provide access for mechanical couplings to join the segment pairs together.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority to and the benefit of U.S. ProvisionalApplication Ser. No. 62/955,806 filed Dec. 31, 2019 titled “SEGMENTEDFLUID END PLUNGER PUMP,” the full disclosure of which is herebyincorporated herein by reference in its entirety for all purposes.

BACKGROUND 1. Technical Field

This disclosure relates generally to hydraulic fracturing and moreparticularly to systems and methods for forming pumps for use inhydraulic fracturing operations.

2. Background

With advancements in technology over the past few decades, the abilityto reach unconventional sources of hydrocarbons has tremendouslyincreased. Horizontal drilling and hydraulic fracturing are two suchways that new developments in technology have led to hydrocarbonproduction from previously unreachable shale formations. Hydraulicfracturing (fracturing) operations typically require powering numerouscomponents in order to recover oil and gas resources from the ground.For example, hydraulic fracturing usually includes pumps that injectfracturing fluid down the wellbore, blenders that mix proppant into thefluid, cranes, wireline units, and many other components that all mustperform different functions to carry out fracturing operations.

Usually in fracturing systems the fracturing equipment runs ondiesel-generated mechanical power or by other internal combustionengines. Such engines may be very powerful, but have certaindisadvantages. Diesel is more expensive, is less environmentallyfriendly, less safe, and heavier to transport than natural gas. Forexample, heavy diesel engines may require the use of a large amount ofheavy equipment, including trailers and trucks, to transport the enginesto and from a wellsite. In addition, such engines are not clean,generating large amounts of exhaust and pollutants that may causeenvironmental hazards, and are extremely loud, among other problems.Onsite refueling, especially during operations, presents increased risksof fuel leaks, fires, and other accidents. The large amounts of dieselfuel needed to power traditional fracturing operations requires constanttransportation and delivery by diesel tankers onto the well site,resulting in significant carbon dioxide emissions.

Some systems have tried to eliminate partial reliance on diesel bycreating bi-fuel systems. These systems blend natural gas and diesel,but have not been very successful. It is thus desirable that a naturalgas powered fracturing system be used in order to improve safety, savecosts, and provide benefits to the environment over diesel poweredsystems. Turbine use is well known as a power source, but is nottypically employed for powering fracturing operations.

Though less expensive to operate, safer, and more environmentallyfriendly, turbine generators come with their own limitations anddifficulties as well. As is well known, turbines generally operate moreefficiently at higher loads. Many power plants or industrial plantssteadily operate turbines at 98% to 99% of their maximum potential toachieve the greatest efficiency and maintain this level of use withoutsignificant difficulty. This is due in part to these plants having asteady power demand that either does not fluctuate (i.e., constant powerdemand), or having sufficient warning if a load will change (e.g., whenshutting down or starting up a factory process).

Space is at a premium at a fracturing site, where different vendors areoften working simultaneously to prepare for a fracturing operation. As aresult, utilizing systems that have large footprints may be undesirable.However, pressure pumpers still need to be able to provide sufficientpumping capacity in order to complete fracturing jobs.

SUMMARY

Applicant recognized the problems noted above herein and conceived anddeveloped embodiments of systems and methods, according to the presentdisclosure, for calibration systems.

Systems and methods of the present disclosure are directed towardforming a multiplunger pump without using a single large block for thefluid end. Reciprocating plunger pumps are used for most hydraulicfracturing operations and are made up of three main components; FluidEnd (FE), Power End (PE), and the Suction Manifold. The fluid endcontains the valves that allow low pressure fluid to be drawn into apressure cavity to be pressurized and discharged by a plunger stroke.This is the most common wear item other than smaller consumables such asseats, valves, plungers, and packing that need to be replacedfrequently. A FE is normally made out of a large single block of metalwhich can restrict the ability to mobilize replacement equipment,replace fluid ends in the field, or manufacture replacements. Thesuction manifold allows for low pressure supply fluid to be drawn intoeach pressure cavity in the FE at a pressure and velocity to reducecavitation during operation. The PE consists of the gear set,crankshaft, connecting rods, crosshead structure and plunger assembliesthat convert rotational motion from a motor(s) or prime mover(s) intolateral plunger strokes at a specific speed in order to draw anddischarge fluid from the pressure cavities in the FE. The embodimentsdescribed in this disclosure utilize the above-described PE structure,which is commonly used for quintuplex (five plunger) or triplex (threeplunger) hydraulic fracturing pumps and expands the structure to nine ormore plungers. Accordingly, the FE is expanded as well, but is segmentedto alleviate the above-described problems of manufacturing, mobility andreplacing FEs in the field.

In an embodiment, a fluid end for a fracturing pump includes a firstsegment, the first segment having a plurality of first suction bores anda first discharge path. The fluid end also includes a second segment,the second segment having a plurality of second suction bores and asecond discharge path. The fluid end further includes a third segment,the third segment having a plurality of third suction bores and a thirddischarge path. The first segment is mechanically coupled to the secondsegment, the second segment is mechanically coupled to the thirdsegment, and each of the first discharge path, the second dischargepath, and the third discharge path are aligned.

In an embodiment, a fluid end for a fracturing pump includes a pluralityof segments coupled together along a discharge axis, each segment of theplurality of segments having a plurality of suction bores. The fluid endalso includes respective interfaces between segment pairs formed byadjacent segments of the plurality of segments, the interfaces couplingthe segment pairs together. The fluid end further includes respectiveaccess areas proximate the respective interfaces, the respective accessareas configured to provide access for mechanical couplings to join thesegment pairs together.

BRIEF DESCRIPTION OF DRAWINGS

Some of the features and benefits of the present disclosure having beenstated, others will become apparent as the description proceeds whentaken in conjunction with the accompanying drawings, in which:

FIG. 1 is a schematic plan view of an embodiment of a fracturingoperation, in accordance with embodiments of the present disclosure;

FIG. 2 is a perspective view of an embodiment of a fluid end; inaccordance with embodiments of the present disclosure;

FIG. 3 is a perspective view of an embodiment of a fluid end, inaccordance with embodiments of the present disclosure;

FIG. 4 is a schematic view of an embodiment of a stroking order, inaccordance with embodiments of the present disclosure; and

FIG. 5 is a flow chart of an embodiment of a method for forming asegmented fluid end, in accordance with embodiments of the presentdisclosure.

While the disclosure will be described in connection with the preferredembodiments, it will be understood that it is not intended to limit thedisclosure to that embodiment. On the contrary, it is intended to coverall alternatives, modifications, and equivalents, as may be includedwithin the spirit and scope of the disclosure as defined by the appendedclaims.

DETAILED DESCRIPTION

The method and system of the present disclosure will now be describedmore fully hereinafter with reference to the accompanying drawings inwhich embodiments are shown. The method and system of the presentdisclosure may be in many different forms and should not be construed aslimited to the illustrated embodiments set forth herein; rather, theseembodiments are provided so that this disclosure will be thorough andcomplete, and will fully convey its scope to those skilled in the art.Like numbers refer to like elements throughout. In an embodiment, usageof the term “about” includes +/−5% of the cited magnitude. In anembodiment; usage of the term “substantially” includes +/−5% of thecited magnitude.

It is to be further understood that the scope of the present disclosureis not limited to the exact details of construction, operation, exactmaterials, or embodiments shown and described, as modifications andequivalents will be apparent to one skilled in the art. In the drawingsand specification, there have been disclosed illustrative embodimentsand, although specific terms are employed, they are used in a genericand descriptive sense only and not for the purpose of limitation.

When introducing elements of various embodiments of the presentdisclosure, the articles “a”, “an”, “the”, and “said” are intended tomean that there are one or more of the elements. The terms “comprising”,“including”, and “having” are intended to be inclusive and mean thatthere may be additional elements other than the listed elements. Anyexamples of operating parameters and/or environmental conditions are notexclusive of other parameters/conditions of the disclosed embodiments.Additionally, it should be understood that references to “oneembodiment”, “an embodiment”, “certain embodiments”, or “otherembodiments” of the present disclosure are not intended to beinterpreted as excluding the existence of additional embodiments thatalso incorporate the recited features. Furthermore, reference to termssuch as “above”, “below”, “upper”, “lower”, “side”, “front”, “back”, orother terms regarding orientation or direction are made with referenceto the illustrated embodiments and are not intended to be limiting orexclude other orientations or directions. Additionally, recitations ofsteps of a method should be understood as being capable of beingperformed in any order unless specifically stated otherwise.Furthermore, the steps may be performed in series or in parallel unlessspecifically stated otherwise.

Embodiments of the present disclosure relate to combining smaller FEblocks into a single large FE. In hydraulic fracturing, fluid pumps aretypically built as either triplex pumps with 3 plungers or quintuplexpumps with 5 plungers. Since the FEs are typically made from a singleblock of steel or alloy steel, most manufactures do not have the toolingto build larger pumps with more than 5 plungers, and most maintenanceequipment used by service companies cannot lift FE blocks any larger orheavier than a quintuplex for replacement on a frac pump. While thepresent Applicant has identified the advantages of a larger pump forelectric frac equipment, the supply chain of manufacturers willing andable to create such pumps is very small. However, these problems can beovercome by connecting 3 triplex FE blocks together with sealing systemsbetween the discharge passages to generate a novemplex (nine plunger)pump. Using a series of triplex FEs enables any manufacturer to createthe smaller components with minor modifications to their existingtriplex designs. The same triplex block segments may also be usable asstand-alone triplex pumps for use in legacy equipment. This wouldincrease vendor pools for purchasing FEs while also keeping inventorysimple as triplex and novemplex pumps can share the same FEs.

Embodiments of the present disclosure may also reduce repair andmaintenance costs. By way of example, a single triplex FE might costaround $30,000 while a novemplex might cost around $90,000. If a singlebore in a single block novemplex FE washes out, the entire FE will needto be replaced. If a novemplex pump is composed of 3 triplex blocksbolted or otherwise coupled together, a single section can be replacedat a third of the cost. This will allow the useful remaining life of theother triplex sections to be utilized until failure. A single triplexsection is also much lighter and can be lifted into place on a wellsiteusing a forklift, light crane, or small service truck crane. A largesingle block novemplex FE may require an overhead crane in a local shopor the use of a larger mobile crane which cannot always be parked closeenough to equipment in the field for servicing. Replacement triplexsections can also be more easily transported between districts and outto well sites without needing large trailers and tractors. For example,if during hydraulic fracturing operations, the fluid supply to thesuction ports of the FE might be hampered to the rear most plungers (7,8, and 9) on a novemplex FE causing cavitation in those cavities of theFE, damage could be mitigated by swapping that triplex portion earlierthan the other portions. For example, a section may be damaged by thecavitation, which could lead to an early failure of 1,000 hours or lesswhile other sections may last 2,000 hours or more.

The most common hydraulic fracturing plunger type pump in the industryis a quintuplex pump with a 2,500 horsepower rating. Currently in theindustry, there is a push by some pump manufacturers to create hydraulicfracturing pumps with power ends and fluid ends capable of operating athigher power levels, such as 5,000 horsepower. This effort is typicallyfocused on electric fracturing units, since electric motors can bepackaged in a much smaller footprint than diesel engine/transmissionprime mover systems. These higher powered pump designs are centeredaround staying with a quintuplex style power ends and fluid ends withthe overall footprint of the pumps remaining very similar to the 2,500horsepower legacy pumps. While it is possible to redesign and strengthenthe PE of a legacy style quintuplex pump to operate at 5,000 horsepower,the FE is still limited to 5 plungers. Essentially, at the 5,000horsepower level, each plunger will now have double the amount of powerpumping through them, thereby likely lessening the life of the FE by50%. However, by utilizing features of the present disclosure, fullutilization of a higher powered prime mover by both the PE and FE withno decrease in life expectancy is enabled.

Embodiments of the present disclosure provide pumps formed from segmentsof FEs rather than a large novemplex pump (9-plungers) made out of asingle block of metal. For example, a novemplex pump may be formed from3 triplex fluid ends connected together with a sealing system betweenthe common discharge ports of the segments. This pump will act as asingle FE block and can achieve far higher fluid rates and HHP.Additionally, using embodiments of the present disclosure enablesscaling up to larger FEs, such as 12 or 15 plunger pumps. Furtheradvantages are found by simplifying supply chains and warehousing byhaving common FEs that can be used in a variety of differentapplications.

FIG. 1 is a plan schematic view of an embodiment of a hydraulicfracturing system 10 positioned at a well site 12. In the illustratedembodiment, pumping units 14 (e.g., pump trucks), which make up apumping system 16, are used to pressurize a slurry solution forinjection into a wellhead 18. An optional hydration unit 20 receivesfluid from a fluid source 22 via a line, such as a tubular, and alsoreceives additives from an additive source 24. In an embodiment, thefluid is water and the additives are mixed together and transferred to ablender unit 26 where proppant from a proppant source 28 may be added toform the slurry solution (e.g., fracturing slurry) which is transferredto the pumping system 16. The pumping units 14 may receive the slurrysolution at a first pressure (e.g., 80 psi to 160 psi) and boost thepressure to around 15,000 psi for injection into the wellhead 18. Incertain embodiments, the pumping units 14 are powered by electricmotors.

After being discharged from the pump system 16, a distribution system30, such as a missile, receives the slurry solution for injection intothe wellhead 18. The distribution system 30 consolidates the slurrysolution from each of the pump trucks 14 and includes discharge piping32 coupled to the wellhead 18. In this manner, pressurized solution forhydraulic fracturing may be injected into the wellhead 18.

In the illustrated embodiment, one or more sensors 34, 36 are arrangedthroughout the hydraulic fracturing system 10 to measure variousproperties related to fluid flow, vibration, and the like. Inembodiments, the sensors 34, 36 transmit flow data to a data van 38 forcollection and analysis, among other things. Furthermore, while notpictured in FIG. 1 , there may be various valves distributed across thesystem. For examples, a manifold (not pictured) may be utilized tosupply fluid to the pumping units 14 and/or to receive the pressurizedfluid from the pumping units 14. Valves may be distributed to enableisolation of one or more components. As an example, there may be valvesarranged to enable isolation of individual pumping units 14.Furthermore, various support units may also include valves to enableisolation. As noted above, it may be desirable to isolate singularpumping units 14 or the like if operation upsets are detected. Thiswould enable operations to continue, although at a lower rate, and maypotential environmental or personnel hazards, as well as preventincreased damage to the components. However, during operations,personnel may be evacuated or otherwise restricted from entering apressure zone. Embodiments of the present disclosure may enable remoteoperation of the valves and, in various embodiments, may enableelectrical control using electric energy provided on site, such asthrough a generator or the like.

A power generation system 40 is shown, which may include turbines,generators, switchgears, transformers, and the like. In variousembodiments, the power generation system 40 provides energy for one ormore operations at the well site. It should be appreciated that whilevarious embodiments of the present disclosure may describe electricmotors powering the pumping units 14, in embodiments, electricalgeneration can be supplied by various different options, as well ashybrid options. Hybrid options may include two or more of the followingelectric generation options: Gas turbine generators with fuel suppliedby field gas, CNG, and/or LNG, diesel turbine generators, diesel enginegenerators, natural gas engine generators, batteries, electrical grids,and the like. Moreover, these electric sources may include a singlesource type unit or multiple units. For example, there may be one gasturbine generator, two gas turbines generators, two gas turbinegenerators coupled with one diesel engine generator, and various otherconfigurations.

In various embodiments, equipment at the well site may utilize 3 phase,60 HZ, 690V electrical power. However, it should be appreciated that inother embodiments different power specifications may be utilized, suchas 4160V or at different frequencies, such as 50 Hz. Accordingly,discussions herein with a particular type of power specification shouldnot be interpreted as limited only to the particularly discussedspecification unless otherwise explicitly stated. Furthermore, systemsdescribed herein are designed for use in outdoor, oilfield conditionswith fluctuations in temperature and weather, such as intense sunlight,wind, rain, snow, dust, and the like. In embodiments, the components aredesigned in accordance with various industry standards, such as NEMA,ANSI, and NFPA.

In an embodiment, a small VED paired with a dedicated electric motorrated for not more than 100HP can be used to rotate the chemicaladditive pump, this motor and VFD can operate at voltages of 240V, 480V,600V, 690V, or 720V. It should be appreciated that while embodiments maybe described with reference to electric motors, in other embodiments,diesel prime movers and hydraulic pumps may also be utilized at thefracturing site, for example, to drive chemical additive pumps. Forexample, a large diesel engine can power an open or closed hydraulicsystem containing at least one hydraulic pump and one hydraulic motor torotate a chemical additive pump. Both of these embodiments will becontrolled by a software control system utilizing a user programmed P&IDloop and calibration factor used to help tune the accuracy of chemicalflow rates and reactions to flow rate changes, as will be describedbelow.

As described above, the pumps utilized in these operations may be pumpswith three or five plungers. However, larger pumps may be desirable withlarger PEs or where larger capacity may be desirable. Accordingly,embodiments of the present disclosure are directed toward systems andmethods for modular or segmented FEs that may be used in fracturingoperations, among other industrial applications. FIG. 2 is a perspectiveview of an embodiment of a novemplex FE 200 that includes a cutawaysection to illustrate various features of the present disclose. Itshould be appreciated that various features have been removed forclarity with the present disclosure. The illustrated FE 200 consists ofthree different triplex FEs 202, 204, 206 that have been coupledtogether along a discharge axis 208 (e.g., perpendicular to the suctionends).

In the illustrated embodiment, a notch 210 has been machined into eachtriplex section 202, 204, 206 to allow for one or more fasteners (notpictured), such as bolts, studs, clamps, etc., to couple adjacent fluidend blocks together. It should be appreciated that a set of fastenersmay be utilized for only two sections or may extend to couple more thantwo sections together. The illustrated notch 210 is arranged above(e.g., axially higher) suction caps 212, but it should be appreciatedthat the notch may be arranged below (e.g., axially lower) the suctioncaps 212 or there may be notches at both above and below locations.

Further illustrated within the cutout section is a second notch 214 inthe rear 216 of the fluid end section, opposite the suction caps 212,where additional and/or alternative connectors may be used to couple thefluid end sections together. The rear section 216 of the FE faces thepower end and is where the plungers penetrate each pressure bore.

A discharge port 218 is illustrated that runs the length of each fluidend section 202, 204, 206. Discharge piping is connected to one or bothends to allow pressurized fluid to be connected to a manifold orwellhead (not pictured). Sealing this connection between each fluid endsection may be accomplished using sealing systems or the like. Forexample, various seals (e.g., elastomer, metallic, etc.) and the likemay be utilized within various grooves formed between interfaces betweenthe sections 202, 204, 26. It should be appreciated that the sealingdesign may be particularly selected depending on where along theassembly the fluid end section is arranged.

A coupling aperture 220 is illustrated at an end 222, which may receivethe one or more fasteners to couple the fluid ends together. In theillustrated embodiment, the coupling aperture 220 is a threaded holethat receives a threaded bolt, but it should be appreciated that otherapertures or receivers may be utilized to enable coupling of the varioussegments. As noted above, while a single aperture is illustrated in thisembodiment, there may be multiple apertures that receive multiplefasteners to couple the sections together. Furthermore, as stated, athreaded fitting is only utilized as an example and various otherfeatures may also be used to couple the sections together. By way ofexample only, clamps may be utilized, or tongue and groove segments maybe used to secure the sections together.

Suction caps are installed along the bores 212. As will be appreciated,there is one suction cap per pressure bore and plunger. It should beappreciated that certain bores/caps have been removed, but thatembodiments of the present disclosure may be directed to a novemplexwith 9 bores/suction caps. In other words, embodiments are directedtoward coupling three triplex FEs together.

As noted above, various components have been removed from FIG. 2 forclarity. By way of example, discharge caps (normally on the top face ofthe fluid end sections) have been removed. These caps would be removedto allow operators access to the discharge valves and discharge port,Additionally, a suction manifold has been removed. In operation, thesuction manifold is on the bottom of the fluid end and allows lowpressure fluid to be supplied evenly to each pressure bore. Thismanifold can be placed on either the top or bottom of a fluid end and isopposite the discharge caps. Discharge irons have also been removed,Discharge irons are a pressure rated iron pipe that is normally boltedto one or both sides of the discharge port. The inside diameter andpressure rating of the iron are determined by the required flow rate andexpected wellhead pressure. Sensor locations are also not noted in FIG.2 . Embodiments may include several sensors such as pressure transducersand vibration monitors. Additional components that have been removedinclude discharge port gaskets, bolt holes, other clamping bolts, andstay rods. Stay rods may hold the fluid end to the power end. They aresimilar to a sleeved bolt design where there is a gap between them toallow a “pony rod” from the power end to be attached to a plunger. Thegap also allows maintenance of packing to prevent fluid leaks where theplungers enter the fluid end. Another example of a component that hasbeen removed are packing lube ports for the plungers.

FIG. 3 illustrates a perspective view of the back side 216 of the FE200. As described above, a cutaway section has been included toillustrate a section notch 214 that includes a fastener location 300where a bolt, stud, or other fastener may be utilized to couple thefluid end sections 204, 206 together. As noted, there may also besealing systems positioned between the fluid end sections. Furthermore,there may be more than one fastener used, along with alternativefastening arrangements. The illustrated embodiment also includes plungerpenetration locations 302. As shown, triplex blocks are used, but itshould be appreciated that other blocks, such as quintuplex blocks, maybe used. The plunger penetration locations 302 illustrate thepenetrations for the plungers in each fluid end section 204, 206.Accordingly, in various embodiments, the sections 202, 204, 206 arecoupled together at both a suction side and a power side, but it shouldbe appreciated that more or fewer areas may be coupled together based onanticipated operating conditions and the like.

FIG. 4 is a schematic illustration of a stroking order 400 that may beutilized with embodiments of the present disclosure. For example, theillustrated embodiment describes a novemplex pump having nine plungers402. The preferred stroking order, or the order in which plungers withinthe fluid end make their respective discharge stroke, is an order whichwill result in the optimum balancing of the loading on the crankshaft.Referring to FIG. 4 , the circles represent the number of plunger boreswithin the FE, and for simplicity are numbered 1 through 9 from right toleft, wherein the plungers 402 would reciprocate within the bores. Thepreferred stroking order would be as shown in the middle row.

This order results in the following number of plungers that have gonethrough their respective discharge strokes adjacent to the plunger thatis stroking next according the shown stroking order. So, after plunger#1 strokes, plungers #4 and #7 go through their respective strokesbefore plunger #2 which is adjacent to plunger #1. Therefore, there weretwo plunger strokes relatively far away from plunger #1 (#4 and #7) thatcompleted their respective strokes before the adjacent plunger to #1stroked. Accordingly, after plunger #2 strokes, plunger #5 and #8complete their stroke resulting in 2 strokes occurring relatively faraway from plunger #2. As shown in the figure, the number of strokes thatoccur between plunger #3 and #4 is 3. The number of strokes that occurbetween plunger #4 and #5 is 2, and so on as the figure shows.Therefore, the loading on the crankshaft from this stroking order isbalanced. It should be appreciated that the illustrated stroking orderis for illustrative purposes only and that other embodiments may havedifferent stroking orders. Furthermore, different arrangements may beestablished based on the number of plungers used.

FIG. 5 is a flow chart of an embodiment of a method 500 for assembling asegmented FE. It should be appreciated that this method, and all methodsdescribed herein, may have more or fewer steps. Moreover, the steps maybe performed in a different order, or in parallel, unless otherwisespecifically stated. In this example, at least two FE segments areprovided 502. As noted above, the FE segments may be configured to becoupled together, and as a result, at two segments may be aligned alonga discharge axis 504. The alignment may correspond to aligningrespective apertures formed in the segments. One or more sealing systemsmay be positioned at an interface between the segments 506. The sealingsystems may include various seals and/or machined components that areutilized to block fluid leakage. The segments may, then be coupledtogether 508. In this manner, a segmented FE may be formed by joiningtogether a selected number of FE segments.

Embodiments of the present disclosure present a number of advantagesover existing systems and methods. As an example, systems and methods ofthe present disclosure may reduce costs by using multiple smaller blocksfor pump manufacturing. As a result, production of a single larger blockmay be cheaper and easier. Furthermore, repairs and/or replacements maybe performed on specific sections, rather than on the entire block.Moreover, inventory control with manufacturers and operations may beimproved. For example, legacy equipment can continue to use triplex andquintuplex blocks while newer equipment can use novemplex (9) orquindenplex (15) pumps composed of the same blocks. In variousembodiments, operators may keep supplies of the sections that may bethen swapped out to replace either the legacy triplex blocks or to makerepairs to the newly formed blocks. Moreover, a vendor pool may beincreased as more companies may be capable of manufacturing smallerblocks.

Embodiments may provider further advantages in the field. For example,the systems described herein may enable easier field swaps because asingle block section (triplex or quintuplex) may be easier to transportand swap out on a frac pump trailer in the field versus a single largenovemplex block. Moreover, utilizing these systems may result in fewerpump trailers on location. For example, a triplex pump can pump at anoptimal fluid rate of around 5 bpm (barrels per minute) whereas a singlenovemplex can discharge up to 12 bpm for an optimal rate. It should beappreciated that these rates are for illustrative purposes only and maybe rounded off and depend of plunger size, discharge pressure, andplunger velocity. A normal frac site needs 90-120 bpm with an additional1.2-18 bpm as spare or standby pumping capability. Accordingly, thenumber of trailers may be reduced through the incorporation of largerpumps. Moreover, fewer trailers may also lead to fewer power cables,thereby decreasing congestion at the site. Additionally, with fewertrailers and power cables required to have the same amount of HHP(hydraulic horsepower) on a frac fleet, operations may be able to reducethe amount of switch gear on electric frac sites. Switch gear iscomposed of the breakers, relays, and bus bars that safely distributeelectricity to connected equipment. As an example, replacing 15quintuplex pumps with 10 novemplex pumps would reduce switch gear by onethird. This reduction in switch gear leads to reduced costs and shrinksthe size of the switch gear trailers.

Systems and methods of the present disclosure may also incorporatelarger power ends to maintain compact and mechanically simple designs.As an example, a single large PE may be utilized with embodiments of thepresent disclosure. However, it should be appreciated that PEs may alsobe similarly segmented, as noted about with respect to the FEs. By wayof example, a PE normally lasts 3-5 times longer than a standard FE andfield swaps are normally not performed. Once assembled, a frac pump mayonly need a PE swap every 6,000-8,000 hours versus an expected life spanof 1,500-2,000 hours for a FE. As a result, larger PEs will still enablelonger overall useful lives when utilized with embodiments of thepresent disclosure. Additionally, embodiments may also incorporatelarger motors or prime movers. That is, embodiments may include aphysically larger and higher HP motor or prime mover to take advantageof the large fluid pumps. While this may take up space and add weightand/or cost to each frac pump trailer, due to quantities of scale andthe advantages obtained by using a larger pump, the cost per horsepowerof an entire fleet will be reduced. Moreover, such a configurationsimplifies equipment rig up by reducing the number of individualtrailers and power cables on a website. Horsepower ranges of3500-5500911P may be desirable to take advantage of the larger fluidpumps, as compared to present ratings of 1750-2500 HHP for triplex andquintuplex designs.

Various embodiments may also incorporate stronger couplers to withstandthe torque of the large motors. Additionally, leak points betweensegments (e.g., at segment interfaces) may be addressed using a varietyof methods. The discharge bore through the fluid ends is typicallymachined horizontally through all of the plunger vertical cross boressuch that the horizontal discharge bore terminates with a machinedflange connection on each side onto which the discharge manifoldconnects. One methodology of sealing between segments includes machiningthe sealing geometry into the side of each FE instead of machining theflange connection geometry such that the sealing interface on one sideof the fluid end could be termed the “male” sealing interface and theopposite side of the fluid end could be termed the “female” sealinginterface. Clamping this interface together could be performed as shownabove. A number of sealing methods are possible, but one embodiment ofthe sealing elements could be to utilize a common D-ring seal in thehorizontal sealing pocket of the “female” sealing interface in additionto a common o-ring seal machined into the vertical face of the “female”sealing interface. The “male” sealing interface on each FE would then beparticularly sized to obtain the desired amount of compression on theseals when the clamping bolts or studs are tightened to connect the FEsegments together. The same methodology would apply to connecting thethird. FE segment into the first pair. Adapters could then be machinedto connect to the two exposed sealing interfaces on the unconnectedsides of group of 3 fluid ends. These adapters may be be designed toconnect to the common legacy discharge manifold components. Embodimentsof the present disclosure may also be utilized with larger trailers. Alarger fluid end, power end, motor, variable frequency drive (VFD), andcooling package may use a larger trailer than traditional systems. Forelectric equipment, trailer sizes have been reduced significantly as thetechnology advanced and became more compact. Applicant has recognizedcapability to lengthening the trailers by 10 or more feet to increasethe MAP.

It should be appreciated that various configurations shown herein arefor illustrative purposes to convey concepts discussed herein, but arenot intended to be limiting. For example, the segmented FE pump that wasused as an example throughout this disclosure is the“Triple-Triplex”-Novemplex, which is a frac pump composed to threetriplex blocks sealed together to prevent fluid leaks to act as a largenovemplex pump powered by a single power end. However, there are severalother usable combinations that could be created while using currentstyles of fluid end blocks, including but not limited to a“Quintuple-Triplex” Quindenplex fluid end. This configuration iscomposed of 5 triplex blocks to create a large 15-plunger pump.Additionally, a “Triple-Quintuplex” Quindenplex fluid end is anotherpossible 15-plunger pump composed of 3 quintuplex blocks. As anotherexample, a “Double-Quintuplex” Decemplex fluid end is a 10-plunger pumpcomposed of 2 quintuplex blocks. It should be appreciated that evennumbers of plungers may be undesirable due to their flow ripple(approximately double odd number plunger pumps). However, embodiments ofthe present disclosure enable a resulting flow ripple better than thatof the industry accepted triplex and comparable to that of the industryaccepted quintuplex due to the number of plungers. In another example, a“Quadruple-Triplex” Duodecaplex fluid end is a 12-plunger pump formed byusing 4 triplex blocks. This is another even numbered plunger pump, butthe flow ripple would be acceptable due to the quantity of plungers. Itshould be appreciated various other configurations may also be enabledby embodiments of the present disclosure.

Various embodiments of the present disclosure may include a plunger andvalve size of 4″ for the novemplex pump. Many current triplex andquintuplex pumps are 4.5″, Some pump down pumps (frac pumps modified forhigher fluid rate and a lower pressure rating) use 5″ components. Allthree of these sizes are industry standards and can be used for theSegmented FE Pump design of the present disclosure. Other nonstandardcomponent sizes of 3.5″, 3.75″, and 4.25″ may also be used. Theadvantages of some of these smaller and intermediate sizes includeproviding a better balance of fluid rate and maximum pressure rating. Itshould be appreciated that various components may be selected, at leastin part, by rod load on the PE and horsepower capability of the primemover. For example, a novemplex PE and FE may be rated for 4500 HHP witha 5000 BHP motor attached; this could allow the pump to achieve fluidrates of 12 BPM at a max pressure of 15,000 psi. Alternatively, the sameFE/PE/Motor combination with a larger plunger and valve size couldachieve fluid rates of 15 BPM at a max pressure of 12,000 psi. Certainshale basins have higher or lower expected frac pressures and frac pumpscan be tailored to meet this requirement with the highest possible fluidrate per pump. This same frac pump could be converted to a pump-downpump with an even larger component size and achieve 18 BPM with apressure rating of 10,000 psi, this would allow use of a single fracpump trailer for pump down whereas normally 2-4 pump trailers arerequired. Fluid end blocks can be made out of stainless steel or carbonsteel, among other materials.

The present disclosure described herein, therefore, is well adapted tocarry out the objects and attain the ends and advantages mentioned, aswell as others inherent therein. While a presently preferred embodimentof the disclosure has been given for purposes of disclosure, numerouschanges exist in the details of procedures for accomplishing the desiredresults. These and other similar modifications will readily suggestthemselves to those skilled in the art, and are intended to beencompassed within the spirit of the present disclosure disclosed hereinand the scope of the appended claims.

We claim:
 1. A fluid end for a fracturing pump, comprising: a firstsegment, the first segment having a plurality of first suction bores anda first discharge path; a second segment, the second segment having aplurality of second suction bores and a second discharge path; and athird segment, the third segment having a plurality of third suctionbores and a third discharge path; wherein the first segment ismechanically coupled to the second segment, the second segment ismechanically coupled to the third segment, and each of the firstdischarge path, the second discharge path, and the third discharge pathare aligned.
 2. The fluid end of claim 1, wherein the first segment iscoupled to the second segment via one or more fasteners.
 3. The fluidend of claim 1, wherein the second segment comprises: a notch formed inthe second segment, the notch having a second aperture aligned with afirst aperture of the first segment.
 4. The fluid end of claim 3,wherein the notch is at least one of axially higher than the pluralityof suction bores or axially lower than the plurality of suction bores.5. The fluid end of claim 3, wherein the notch is formed on at least oneof a suction side of the second segment or a back side of the secondsegment.
 6. The fluid end of claim 1, wherein the plurality of firstsuction bores includes three suction bores, four suction bores, or fivesuction bores.
 7. The fluid end of claim 1, wherein each of theplurality of first suction bores, the plurality of second suction bores,and the plurality of third suction bores has an equal number ofrespective suction bores.
 8. The fluid end of claim 1, furthercomprising: a sealing system arranged at an interface between the firstsegment and the second segment, the sealing system including at leastone seal to control flow at the interface.
 9. The fluid end of claim 1,wherein the plurality of first suction bores, the plurality of secondsuction bores, and the plurality of third suction bores have acumulative number of bores equal to at least one of nine bores, tenbores, twelve bores, or fifteen bores.
 10. The fluid end of claim 1,wherein a first end of the first segment is machined as a female end anda second end of the first segment is machined as a male end.
 11. A fluidend for a fracturing pump, comprising: a plurality of segments coupledtogether along a discharge axis, each segment of the plurality ofsegments having a plurality of suction bores; respective interfacesbetween segment pairs formed by adjacent segments of the plurality ofsegments, the interfaces coupling the segment pairs together; andrespective access areas proximate the respective interfaces, therespective access areas configured to provide access for mechanicalcouplings to join the segment pairs together.
 12. The fluid end of claim11, wherein the mechanical couplings are fasteners.
 13. The fluid end ofclaim 11, wherein each respective access area includes an aperturealigned along the discharge axis, the aperture aligning with an adjacentcoupling aperture of the segment pairs.
 14. The fluid end of claim 11,wherein a single access area is associated with a respective interface.15. The fluid end of claim 11, wherein the respective access areas areat least one of axially higher than the plurality of suction bores oraxially lower than the plurality of suction bores.
 16. The fluid end ofclaim 11, wherein the respective access areas are formed on at least oneof a suction side of the respective segments or a back side of therespective segments.
 17. The fluid end of claim 11, wherein theplurality of suction bores is equal for each segment of the plurality ofsegments and include three suction bores, four suction bores, or fivesuction bores.
 18. The fluid end of claim 11, further comprising:respective sealing systems arranged at the respective interlaces, therespective sealing systems including at least one seal to control flowat the respective interfaces.
 19. The fluid end of claim 11, wherein theplurality of suction bores have a cumulative number of bores equal to atleast one of nine bores, ten bores, twelve bores, or fifteen bores. 20.The fluid end of claim 11, wherein a first end of each segment ismachined as a female end and a second end of each segment is machined asa male end.